1. Technical Field
The present invention is directed toward an apparatus and method for determining gas and liquid rates from gas continuous production wells using a differential pressure flow meter installed in series with a SONAR flow meter.
2. Background Information
Flow measurement using a differential pressure type flow meter in combination with a SONAR type flow meter (collectively referred to as a “DP plus SONAR flow meter system”) is well known within the oil and gas field. DP flow meters are widely used to monitor gas production and are well-known to over-report the gas flow rate in the presence of liquids. This tendency to over report due to wetness indicates a strong correlation with the liquid to gas mass ratio of the flow. SONAR flow meters, in contrast, are known to accurately report gas flow rates with less sensitivity to liquid loading. As such, this dissimilar sensitivity to wetness associated with SONAR flow meters and DP flow meters provides a practical means for accurately measuring the gas flow rate and the liquid flow rate of a wet gas flow. The use of a DP plus SONAR flow meter system to evaluate a fluid flow has limitations, however.
Although the difference in wetness sensitivity between DP and SONAR flow meters can be utilized advantageously to determine the gas flow rate and the liquid flow rate, the accuracy of those determinations is based on the assumption that both types of flow meters report the same gas flow rates under dry gas conditions. FIG. 1 illustrates the convergent/divergent reporting characteristics of a DP flow meter and a SONAR flow meter. Specifically, FIG. 1 illustrates the relationship of the Lockhardt-Martinelli Number to the output data 20 of a DP flow meter, the output data 22 of a SONAR flow meter, and illustrates a difference 24 between the two. If both meters do not report the same flow characteristic values in a dry gas condition, any liquid rate reported by the DP plus SONAR flow meter system will be inaccurate because the liquid rate determination is a function of the difference in the gas rates reported by the individual system; i.e., any offset in the two meters under dry gas conditions will result in an error in the reported liquid rate. Thus, the accuracy of the measurement of liquids within a DP plus SONAR system is directly related to dry gas rates reported by each flow meter, or any offset there between.
There are many sources for systematic offsets between the dry gas rate determined by two flow meters installed on a line in series in general, and in particular, between a DP flow meter and a SONAR flow meter. The offsets in dry gas flow rates can be due to several potential sources, including, but not limited to, the following: 1) error in measured DP; 2) errors in flow geometry; 3) the impact of non-fully developed pipe flows; 4) the impact of pipe wall roughness; 5) errors in flow stream composition; and 6) errors in the PVT models for the well stream composition.
In the event of an offset, an in-situ calibration would be required to accurately determine absolute liquid production rates. Since providing an accurate measure of produced gas and liquid rates is often a primary reason for performing well surveillance activities, the need for in-situ calibration (typically provided using either a well test separator or other method) limits the utility of DP plus SONAR for many applications.
The performance of a well from a gas reservoir is often impacted by water from the reservoir. In this scenario, the hydro carbon composition of flows from such wells tends to be fairly constant with time, although the amount of water within the flow tends to increase over time. Tracking the amount of water produced from the well is important for many reasons, including predicting reservoir performance, estimating well deliverability, scheduling of well interventions, and optimizing surface production facilities.
The process of producing liquids from a gas continuous well can be quite complex and time varying. The quantity of liquids produced can be determined using a number of different parameters such gas and liquid properties, flow rates, and pipe layout and flow regimes. After a shut-in period, operators typically flow a multiphase well at given choke setting for a significant period of time to achieve stabilized flow rates. This stabilization period allows the multiphase flow within the wellbore, risers, and surface piping to reach conditions representative of typical production conditions. The time period required for the liquid and gas rates to stabilize is typically several hours to several days.
When a well is “shut-in” (i.e., no flow through the well), the gas and liquids within the well separate due to gravity. The liquids within the well bore will, depending on the well geometry, fall to the bottom of the well. The gas will rise to the top. When the choke on the well is opened after a shut-in period, the well will typically flow dry gas initially. It takes a finite period of time for the well to “lift” the liquids to the surface. During the initial flow period after a shut-in, the well can flow essentially “dry gas”; i.e., gas free of any free liquids.
What is needed is a practical in situ method and apparatus for calibrating a DP plus SONAR flow meter system.